Declining pressures in natural gas fields has resulted in the use of rotary screw compressors as wellhead boosters. Rotary screw compressors are designed for low pressure applications with inlet pressures up to 100 psig and discharge pressures up to 350 psig.
Rotary screw compressors are described in U.S. Letters Patent Nos. 6,506,039, 6,217,304, and 6,216,474, the disclosures of which are incorporated herein by reference. The main components include one set of male and female helically grooved rotors, a set of axial and radial bearings, and a slide valve, which are all encased in a common housing. As the rotors begin to un-mesh, the male rotor lobe will roll out of the female rotor flute. The volume vacated by the male rotor will fill with suction gas. The further un-meshing of the rotors results in an increase in the volume of gas filling the flute of each rotor.
Gas will continue to enter each flute until the rotor lobes roll out of mesh with each other. As they finish un-meshing, the flutes pass by the edge of the suction port which closes them off from the system. This is the point where the maximum volume of each flute occurs and represents the suction volume of the flute. The suction volume is the volume of trapped gas within the flute at the end of the suction process. The displacement of the rotary screw compressor can be determined by multiplying the volume of the input gas in the male and female flute by the number of lobes on the male rotor and then multiplying this figure by the rotor rpm.
The compression process begins once the suction process is over and the input volume established. The rotors continue to rotate and begin to mesh together along the bottom. The male rotor lobe moves into the female flute and reduces the volume in the flute. The compression process will continue until the compressed gas is discharged through the discharge port.
In an individual flute containing trapped gas, there are two lobe tips: one on the discharge side of the flute and one on the backside of the flute. The tip on the discharge side is referred to as the leading tip. The leading tip will be the first one to reach the discharge port. The second tip is called the trailing tip. As the leading tip of the rotor passes by the edge of the discharge port, the compression process is over and the gas will be forced into the discharge line. The discharge volume is the volume of trapped gas in the flute right before the leading tip of the rotor passes the discharge port. The discharge process continues until the male rotor lobe has completely rolled into the female flute, which displaces all of the gas and any lube oil remaining in the threads (lube oil may be injected into the rotary screw compressor to lubricate parts).
Rotary screw compressors typically have two discharge ports: an axial port and a radial port. The radial port is a V-shaped cut in the slide valve and the axial port is a butterfly shaped port machined in the end casing of the compressor between the bearing bores. Certain rotary screw compressors are designed to operate with lubrication. Those designed for lubrication require the addition of lube oil to provide sealing between rotor lobes and the casing and the male and female lobes where compression occurs. Lube oil is also required for lubrication of the bearings and shaft seals and to reduce the heat of compression in the compressor.
The lube oil system on a rotary screw compressor is a closed loop system. The oil is injected in several locations with the main oil injection port feeding the rotors directly and with smaller lines feeding other points for seals and bearings. Injected oil will drain to the rotors where it combines with the gas. The gas and oil mixture is discharged from the compressor. The gas and oil are separated from each other downstream.
A typical rotary screw compressor system is described in “Screw Compressors: A Comparison of Applications and Features to Conventional Types of Machines,” J. Trent Bruce, Toromont Process Systems, Calgary, Alberta, Canada, and is depicted in FIG. 1, which illustrates a prior art flow diagram for natural gas screw compressor system 10.
As shown in FIG. 1, inlet line 11 feeds wet natural gas (gas containing water vapor) and other free liquid and solid contaminants to suction scrubber 12. Suction scrubber 12 removes the free liquid and solid contaminants from the wet natural gas. The contaminants are removed from suction scrubber 12 through drain/dump line 13 and thereafter disposed.
The wet natural gas is taken off the top of suction scrubber 12 and fed through line 14 to rotary screw compressor 15 where it mixes with the lubricating oil that is injected into rotary screw compressor 15 as described below. The lubricating oil is typically a synthetic product. Rotary screw compressor 15 compresses the wet natural gas. The compressed wet natural gas and lubricating oil mixture is discharged from rotary screw compressor 15 through line 16 to gas/oil separator 17.
Separator 17 separates the lubricating oil from the compressed wet natural gas. Typical oil carry over rates from separator 17 are in the 10 ppm range. The lubricating oil accumulates in the bottom of separator 17. The compressed wet natural gas (free of the lubricating oil) is discharged from separator 17 and is fed through line 18 to air cooler 19.
In air cooler 19, the compressed wet natural gas is cooled from normal discharge temperatures of 170-200° F. down to about 100° F. The cooled compressed wet natural gas is then fed from air cooler 19 through line 20 off skid for connection to the field piping and further processing. Such further processing may include removal of the water vapor entrained within the compressed natural gas by conventional dehydrating processes which are described below. Other contaminants may also need to be removed from the compressed natural gas, as for example, CO2 and/or H2S contaminants. The compressed natural gas may also have to undergo sweetening processing.
The lubricating oil accumulated in the bottom of separator 17 is fed from separator 17 through line 21 to oil cooler 22. Oil cooler 22 cools the lubricating oil from a discharge temperature down to 140-160° F. To cool the lubricating oil, a conventional antifreeze composition (e.g., a water/glycol mixture) is pumped into one side of oil cooler 22 within line 27 and acts as a heat exchanger drawing out the heat in the lubricating oil. The antifreeze composition exits oil cooler 22 at line 28 where it is fed to pump 29. Pump 29 pumps the antifreeze composition through line 30 and into air cooler 19 which cools the antifreeze composition before sending it back through line 27 and into oil cooler 22.
The cooled lubricating oil is fed from oil cooler 22 through line 23 to rotary screw compressor 15 where it is injected into the rotors and reused as a lubricant. Line 24 diverts some of the cooled lubricating oil to oil filter 25 which filters the oil down to about 10 microns. The filtered oil is fed from oil filter 25 through line 26 to rotary screw compressor 15 where it is injected into the bearings and shaft seals and reused as a lubricant.
The compressed wet natural gas obtained after undergoing rotary screw compression still contains water vapor dispersed therein. This is likely because natural gas produced from low-pressure wells normally has large amounts of saturated water vapor entrained therein. The presence of water vapor in natural gas is problematic. Water vapor may cause corrosion, clogging, and other water related damage in the equipment storing or transporting the gas. Industry practice has been to remove the water vapor from the natural gas to prevent such problems.
The most common process for removing water vapor from natural gas is glycol dehydration. The process of glycol dehydration is described in U.S. Letters Patent Nos. 5,453,114, 6,004,380, 5,536,303, 5,167,675, 4,010,065, 5,766,313, and 6,238,461, the disclosures of which are incorporated herein by reference.
A conventional prior art glycol dehydration system 31 is illustrated in FIG. 2. The system includes absorption column 32 in which a wet gas stream is supplied via line 33 to absorption column 32 and passes upwardly through absorption column 32 and out of absorption column 32 via dried gas line 34. A dry glycol stream (lean absorbent) is fed to the upper portion of absorption column 32 via line 35 with a wet glycol stream (water and light aromatic hydrocarbon laden absorbent stream) being recovered from the lower portion of absorption column 32 and fed via line 36 to regenerator 37. A fuel gas stream is passed to regenerator 37 via line 40 and combusted in an amount sufficient to dry the wet glycol from line 36 to produce a lean absorbent stream which is fed through line 38 to pump 39 which pumps the lean absorbent stream to absorption column 32 via line 35. The fuel gas in line 40 is fed through control valve 41 which is regulated by a thermocouple (not shown) in operative contact, as demonstrated by line 42, with regenerator 37. Pump 39 is a gas-driven pump and is driven by the flow of fuel gas in line 40.
In regenerator 37 the water and light aromatic hydrocarbon containing solvent is dried. The water and light aromatic hydrocarbon vapors which were absorbed by the glycol are discharged to the atmosphere through vent line 44. The flue gas is discharged from regenerator 37 through line 42. The dried glycol is fed from regenerator 37 through line 38 to pump 39 and then back to absorption column 32 via line 35. Although not shown, the dried glycol stream exiting regenerator 37 may be passed through a cooler to cool the glycol stream before it is delivered to pump 39.
U.S. Letters Patent No. 6,688,857 describes a system for compressing natural gas that is used to fire a micro-turbine to produce electricity. The system uses a rotary positive displacement compressor to compress natural gas. A lubricating fluid, e.g., glycol or a glycol/water mixture, is fed to the compressor to effect lubrication. A separator separates the natural gas from the glycol fluid. The glycol fluid, which contains water absorbed therein, is processed in a dehydrator to remove the water. The glycol fluid may be cooled by a cooler disposed between the dehydrator and the compressor. The glycol fluid is returned to the compressor to lubricate, seal, and cool the compression process. The system differs from the present invention in that it uses a rotary displacement positive displacement compressor and not a rotary screw compressor. In addition, the system is primarily concerned with dehydrating the glycol/water lubricating fluid and not with dehydrating the natural gas. The system does not describe the operational connectivity between the engine for the compressor and a glycol pump nor the use of exhaust from the engine to provide a heating source for a reboiler.
As described above, low-pressure wells pose technical and economic problems in part due to their high-water content. As reservoir pressures continue to fall, the costs associated with dehydrating wet natural gas produced from these low-pressure make it economically unfeasible to produce natural gas. Standard dehydrating equipment has proven to be economically inefficient or unfeasible with lower pipeline and reservoir pressures. Operators are unwilling to produce natural gas from low-pressure wells because equipment costs required to produce and process the gas (e.g., dehydration) do not justify the potential return on their investment. Efforts have been made to overcome the problems associated with low-pressure wells by the use and/or development of new technologies. Despite these efforts, the need still exists to make low-pressure wells economically feasible to operate by reducing operational costs.